BP's “Orgas” kinetic scheme, was created in the 1980s-early 1990s to model the generation of hydrocarbon fluid (oil and gas) in a reservoir source rock and hence predict the oil and gas volume expelled from organic matter associated with different types of source rock. The Orgas scheme uses different chemical kinetics to describe the generation of oil and gas from organic matter types called “organofacies” which have been defined by BP. Organic matter preserved in basins is mainly bound into an organic polymer (kerogen) which requires the input of heat before it breaks down into oil and gas. This breakdown occurs typically at temperatures of between 100° C. and 230° C. depending on kerogen type. Expulsion of oil and gas does not occur until the kerogen is saturated with oil and gas. Adsorption coefficients for oil and gas are defined based on observed levels of oil and gas in source rocks.
The Orgas scheme uses five different organofacies types. These types relate to the type of organic matter preserved in different types of depositional environments and each type differs in that they generate oil and gas at different temperatures with different chemical kinetics. Different kinetics of oil and gas generation have been established for each organofacies type from laboratory experiments and from observations of naturally heated source rocks in actively generating basins. Organofacies type is a key factor in determining the type and quantity of hydrocarbon fluid that is released upon heating. The link between organofacies type and depositional environment enables reservoir engineers to predict what type of source rock may be present when samples are unavailable.
Once the organofacies type of the source rock has been defined, the next step is to define the richness of the source. The basic measurement which defines this is the total organic carbon content (TOC) which is usually expressed as wt % of organic components of the rock. This organic carbon is sub-divided into reactive and inert fractions and the reactive part can be either oil-prone or gas-prone, generating predominantly oil or gas upon heating.
To determine how much reactive and inert kerogen is present in a source rock, samples of the source rock are heated in a Rock-Eval™ pyrolysis type apparatus at a temperature of between 250° C. and 550° C. The mass of oil and gas that evolve from the source rock with increasing temperature are measured and are divided up into two main peaks—P1 and P2, which are normally expressed as kg/tonne or parts per thousand mass of petroleum per mass of rock. P1 is a measure of the free petroleum in the source rock evolving at lower temperature than the P2 peak, which represents oil and gas generated from breakdown of kerogen.
The temperature at which the P2 peak is at its maximum is called the Tmax value, usually expressed as ° C. This can be a valuable indicator of the thermal stress experienced by a source rock.
In order to express how much of the total carbon is reactive, the term hydrogen index (HI) is defined as:HI=100*P2/TOC  (Eq. 1)
The units are parts per thousand of carbon or mg/gC. Good oil-prone source rocks have HI values in excess of 500 mg/gC whereas lean source rocks tend to have HI values of 100-150 mg/gC or less.
The Hydrogen Index parameter determines how much petroleum could be generated from a source rock, but to know how much of this would be oil and how much would be gas, the Gas-Oil Generation Index or GOGI value is measured. This involves performing the Rock-Eval™ heating experiment described above, except that the P2 peak is analysed by gas chromatography to determine the overall yield of gas and the overall yield of oil from the kerogen breakdown A good oil-prone kerogen has a GOGI value of 0.2 or less whereas gas-prone kerogens have GOGI values in excess of 1.
The free oil in a source rock is measured by the P1 peak and to express this as a fraction of the overall carbon, the P1TOC (or TI—Transformation Index) parameter is defined as:TI=100*P1/TOC  (Eq. 2)The units are mg/gC. This free oil affects how much oil and gas needs to be generated from the kerogen before expulsion can take place as effectively there is some pre-existing oil saturation of the kerogen before thermal generation occurs.
The final parameter needed to define overall yield of petroleum from a source rock is its net thickness. The thickness of the source layer helps in calculating the overall volume of hydrocarbons generated. Many of the rock properties are calculated on a ‘per km2 of rock’ basis, hence they can be scaled up depending on the areal extent of a source rock. The Orgas scheme calculates initial and generated masses, normalising them to unity initially. When kerogen breaks down to form oil and gas, oil and gas fractions are split between expelled and retained but overall the sum of all carbon masses is still unity. The relative proportions of reactive and inert carbon are calculated from the input values for hydrogen index, free oil (based on TI) and GOGI.
Each organofacies has its own set of kinetic constants to define oil and gas generation. Kerogen breakdown is split into a separate oil-fraction and gas-fraction, each with its own set of constants. As only a part of the generated oil is expelled from the kerogen, the remnant oil cracks to gas as thermal stress increases and the Orgas scheme calculates the extent of oil-to-gas cracking within the source rock using a first-order kinetic scheme.
The Orgas scheme sets a threshold for oil and gas adsorption within the kerogen and only when these thresholds are overcome can oil and gas be expelled (released). Oil and gas are defined herein by the carbon numbers of their constituent chemicals with gas having a carbon number in the range of C1-C5 (for example, methane, ethane, propanes, butanes, pentanes) and oil having a carbon number of C6 or greater.
In the original Orgas scheme, two adsorption constants were defined for oil and gas—ao and ag—expressed as mg/gC. Corresponding separate oil and gas thresholds for expulsion are referenced to the carbon content within the source rock and as the source rock generates oil and gas, the overall carbon content decreases.
This scheme has run into difficulties for some organofacies types as it has been realised that the oil-prone source rocks could generate enough oil to reach the oil expulsion threshold, but not enough gas to reach the gas expulsion threshold and so the initial expelled fluid was predicted to contain no gas or has a zero gas to oil ratio (GOR).
The foregoing explains how oil and gas are generated under thermal stress, i.e. thermogenically. It is also understood that gas (e.g. methane) can be generated from the action of bacteria, i.e. biogenically, on organic matter in organic rich source rocks. The interaction between bacteria and organic matter during deposition and burial is complex with a variety of types of bacterial active during different stages of burial. Methane is generated in the methanogenesis zone either by the process of fermentation whereby acetate anions are generated and are subsequently reduced to methane and carbon dioxide or by reduction of carbon dioxide (CO2). Originally CO2 reduction was thought to be dominant in marine environments and fermentation dominant in freshwater environments. This is supported by hydrogen isotope data from gases generated in these different environments; however, recent studies indicate that acetate fermentation is the dominant process overall. The hydrogen isotope data are now thought to reflect differences in waters contained in the pores of the source rock rather than the type of bacteria operating in the marine or freshwater environment. Existing kinetic models consider only thermogenically generated oil and gas.
Recent exploration and production of unconventional hydrocarbon resource plays has demonstrated that the Orgas scheme will underestimate the amount of hydrocarbon fluid that is retained within the source rock. For example, data from shale gas plays, where thermally mature source rocks have been penetrated, show that large volumes of gas are retained in source rocks. This would not have been predicted by the Orgas scheme. In addition, this observed residual gas implies that less gas would have been expelled than the Orgas scheme was predicting.
It is important to predict reliably the volume and physical properties of the oil and gas retained in the source rock as this is sought for production from shale gas, coal bed methane and biogenic gas plays, for example by artificially fracturing (“fracking”) the rock to allow the release of previously trapped gas. Hence the gas in place within such source rocks cannot be reliably predicted using the existing kinetic models which have been implemented within the commercially available software tools. Conversely, less oil and gas has been expelled in reality from the source rock than the Orgas scheme predicts, which impacts pre-drill volumetric predictions for petroleum in conventional plays.